Hydraulic fracturing is well established in the oil industry. In conventional hydraulic fracturing as practiced by industry, the direction of fracture propagation is primarily controlled by the present orientation of the subsurface ("in-situ") stresses. These stresses are usually resolved into a maximum in-situ stress and a minimum in-situ stress. These two stresses are mutually perpendicular (usually in a horizontal plane) and are assumed to be acting uniformly on a subsurface formation at a distance greatly removed from the site of a hydraulic fracturing operation (i.e., these are "far-field"in-situ stresses). The direction that a hydraulic fracture will propagate from a wellbore into a subsurface formation is perpendicular to the least principal in-situ stress.
The direction of naturally occurring fractures, on the other hand, is dictated by the stresses which existed at the time when that fracture system was developed. As in the case of hydraulic fractures, these natural fractures form perpendicular to the least principal in-situ stress. Since most of these natural fractures in a given system are usually affected by the same in-situ stresses, they tend to be parallel to each other. Very often, the orientation of the in-situ stress system that existed when the natural fractures were formed coincides with the present-day in-situ stress system. This presents a problem when conventional hydraulic fracturing is employed.
When the two stress systems have the same orientation, any induced hydraulic fracture will tend to propagate parallel to the natural fractures. This results in only poor communication between the wellbore and the natural fracture system and does not provide for optimum drainage of reservoir hydrocarbons.
Coulter, in U.S. Pat. No. 4,157,116, issued June 5, 1979 teaches a method for reducing fluid flow from and to a subterranean zone contiguous to a hydrocarbon producing formation which includes the steps of initially extending a common fracture horizontally into the zone and into the formation to locate a portion of the fracture in the zone and the formation. A porous bed of solid particles is then introduced into that portion of the fracture located in the zone. A removable diverting material, such as a gel, is thereafter introduced into the portion of the fracture located in the formation and adjacent the locus of the bed of solid particles to block the portion of the fracture occupied by the diverting material to a selected fluid sealing material. The selected sealing material is introduced to the interstices of the particles in the porous bed, and is set to a fluid-impermeable seal to impede fluid flow to and from said zone. The diverting material is subsequently removed to facilitate hydrocarbon production from the formation.
Dill et al. in U.S. Pat. No. 4,527,628 issued July 9, 1985 teach a method of temporarily plugging a subterranean formation using a diverting material comprising an aqueous carrier liquid and a diverting agent comprising a solid azo compound having an azo component and a methylenic component.
Therefore, what is needed is a method whereby the direction of hydraulic fracture propagation can be diverted dendritically so as to cut into a natural fracture system and link it to the wellbore in order to increase hydrocarbon productivity and cumulative recovery.